ML20137E403

Insp Repts 50-269/85-37,50-270/85-37 & 50-287/85-37 on 851008-1111.Noncompliance Noted:Failure to Document Malfunctioning Valve 3LP-2 in Reactor Operator & Senior Reactor Operator Log

ML20137E403
Person / Time
Site:	Oconee
Issue date:	11/21/1985
From:	Bryant J, Dance H, King L, Sasser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20137E374	List: ML20137E370 ML20137E382 ML20137E403
References
50-269-85-37, 50-270-85-37, 50-287-85-37, NUDOCS 8511270251
Download: ML20137E403 (12)

See also: IR 05000269/1985037

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UNITED STATES

[p.08 'o . NUCLEAR REGULATORY COMMISSION

[ p REGION il

g ,. j 101 MARIETTA STREET, N.W..

• 4 ATLANTA. GEORGI A 30323

%...../

-Report Nos:

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50-269/85-37, 50-270/85-37, and 50-287/85-37

Licensee: Duke Power Company

422 South Church Street

Charlotte, N.C. 28242

Facility Name: Oconee Nuclear-Station

Docket Nos.: 50-269, 50-270, 50-287

License Nos.: DPR-38, DPR-47, and DPR-55

Inspection Conducted: October 8 - November 11, 1985

Inspectors:

'

J. . Brya'nt

W !d 'f

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511 <[

Date Signed

M. K.-Sasser

u itkd

Date' Signed

h k \\ ll W

L. P. M ng 'f Date 'Signe:1

-Approved by: W

H. C. Dance, Section Chief

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Date Figned

Division of Reactor Projects

SUMMARY

Scope: This routine, unannounced inspection entailed 344 inspector hours on site

i n - the areas of - operations, surveillance, maintenance, followup of events,

startup from refueling, station modifications, onsite review committee, and

review of LERs, IFIs, and IE Bulletins.

Results: Of. the eight areas inspected, no items of noncompliance or deviations

-were identified in seven areas; one item of noncompliance was found in one area.

Failure to document the malfunction of valve 3LP-2 in the RC and SR0 log.

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B511270251 851122 9

PDR ADOCK 0500

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REPORT DETAILS

1. Licensee Employees

Persons Contacted

• M. S.~ Tuckman, Station Manager

• J. N. Pope, Superintendent of Operations

• R. T. Bond, Compliance Engineer-

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• T. C. Matthews, Technical Specialist

• H. R. Lowery, Shift Operating Engineer

• W. E. Martin, Maintenance Services Engineer

• R. Ledford,- QA Surveillance Supervisor

T. B. Owen, Superintendent of Maintenance

T. C. Barr, Superintendent of Technical Services

Other licensee employees contacted included technicians,- operators,

mechanics, security force members, and staff engineers.

Resident Inspectors

J. C. Bryant

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• M. K. Sasser

L. P. King

• Attended exit interview.

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-2. Exit Interview

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~The inspection scope and findings were summarized on November 12, 1985, with

those persons indicated in paragraph I above. The licensee acknowledged the

violation discussed in paragraph 9. The licensee did not identify as

proprietary any of the materials provided to or reviewed by the inspectors

during this inspection.

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3. Licensee Action on Previous Enforcement Matters

Not inspected.

4. Unresolved Items

Unresolved items were not identified on this inspection.

5. Plant Operations

The , inspectors reviewed plant operations throughout the reporting period to

verify conformance with regulatory requirements, Technical Specifications

(TS), and administrative controls. Control room logs, shift turnover

[ records and equipment removal and restoration records were reviewed

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routinely. Interviews were conducted with plant operations, maintenance,

chemistry, health physics and performance personnel.

Activities within the control rooms were monitored on an almost daily basis.

Inspections were conducted on day and on night shifts, during week days and

on weekends. Some inspections were made during shift change in order to

evaluate shift turnover performance. Actions observed were conducted as

required by:0perations Management Procedure 2-1. The complement of licensed

personnel on .each shift inspected met or exceeded the requirements of TS.

Operators were responsive to plant annunciator alarms and were cognizant of

plant conditions.

Plant tours were taken throughout the reporting period on a routine basis.

The areas toured included the following:

Turbine Building

Auxiliary Building

Units 1,2, and 3 Electrical Equipment Rooms

Units 1,2, and 3 Cable Spreading Rooms

Station Yard Zone within the Protected Area

Unit 3 Reactor Building

Keowee Hydro Station

During the plant tours, ongoing activities, housekeeping, security,

equipment status, and radiation control practices were observed.

Unit 1 began the report period in cold shutdown mode for repair of steam

generator tube leaks. The unit had been shutdown on October 7. During the

short outage, 3 tubes were plugged, one was a known leaker and the other two

were found to have less than the minimum required wall thickness. On

October 18 the reactor was taken critical and power ircreased to 100%.

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On October 20 the unit I reactor coolant system (RCS) leakage calculations

indicated greater than normal leakage, amounting to approximately 0.8

gallons per minute (gpm). Operations began running leakage calculations on

a more frequent basis and measures were taken to identify the source of the

leakage. Several of the calculations- indicated leakage slightly greater

than the TS limit of 1 gpm unidentified; however, subsequent confirmatory

calculations would indicate slightly less than 1 gpm. The overall average

of the calculations was 0.75 gpm. Following several reactor building tours

as well as many RCS equipment manipulations, the source of the leakage was

determined to be the drain valve from the nitrogen decay tank in the RCS

letdown line. After performing a safety evaluation the RCS leak rate

procedure was corrected to account for 0.75 gpm known leakage from the

nitrogen decay tank to the reactor building normal sump. TSs allows

operations with up to 10 gpm identified leakage.

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- The unit 1 leak remained stable until November 8 at which time an increase

on approximately 0.5 gpm was observed. The unit was shutdown on November 9

at 2:30 a.m., the decay tank drain valve was leak repaired, and the unit was

returned to criticality at 10:35 p.m. on the same day. At the end of the

report period the unit was operating at 97.5% power, slightly reduced due to

problems in the main feedwater pump A control system.

Unit 2 began the report period operating at 100% power and continued at that

power level throughout the period.

Unit 3 began the report period at hot shutdown, continuing with unit-startup

, activities following a refueling outage. The reactor was taken critical at

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1:00 a.m. on October 8. The unit was operated at 60% power until October 11

when power was increased to 100%.

During the unit 3 startup activities, several sources of RCS leakage had

been identified, including leakage past both reactor vessel 0-rings.

.Because of this leakage the licensee was planning to shut down the reactor

on or about October 18 for 0-ring replacement. However, on October 14 the

RCS leakage increased and, upon inspection, unidentified leakage was noted

coming from the 3A2 cavity. Based on this new leakage and an increasing

trend the reactor was taken to hot shutdown. Further inspection identified

the leakage to be from a Graylock fitting on the cooling jacket of reactor

coolant pump 3A2. The reactor was taken to cold shutdown, the reactor

vessel head removed, and 0-rings replaced. Other known sources of leakage

were repaired.

During the process of taking the reactor to cold shutdown, problems were

encountered in placing the LPI decay heat removal system in service, due to

the inability to open the loop isolation valve, 3LP-2, from the control room

hand switch. This problem is discussed in greater detail in paragraph 9.

Unit 3 was taken critical at.11

56 p.m. on October 24 following the RCS leak

repairs. During power escalation the reactor tripped from 10% power on loss

of both feedwater pumps. See paragraph 8 for further details. The reactor

was taken critical again at 11:56 p.m. on October 24 and power escalated to

100%. Unit 3 operated at 100% until 12:08 a.m. on November 7, when it began

-to shutdown due to an overheated bearing on the high pressure turbine. The

turbine was taken offline at 12:59 a.m. and the reactor was shut down at

4:20 a.m. The bearing was replaced during the refueling outage and the i

removed bearing has not yet been refurbished. The shutdown is anticipated

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to last 5 to'14 days.

6. Surveillance Testing

The surveillance tests listed below were reviewed and/or witnessed by the

inspectors to verify procedural and performance adequacy. The completed

tests reviewed were examined for necessary test prerequisites, instructions,

~ acceptance criteria, technical content, authorization to begin work, data

collection, independent verification where required, handling of

deficiencies noted, and review of completed work.

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Thef tests witnessed, in whole or in part, were inspected to determine that

approved procedures were available, test equipment was calibrated,

t prerequisites were cet. tests were conducted according to procedure, test

results were acceptaLse a.,d systems restoration was completed.

Surveillances witnessed in whole or in part are as follows:

OP/0/A/1105/09 CRD Patch Verification After Refueling on Head

Removal, Unit 3

IP/0/A/330/2D CRD Patching Scheme and Functional Cabling, and

Patching Test, Unit 3

IP/3/A/0305/IE RPS Channel "A" Temperature Calibration

PT/0/A/0150/22D Individual Valve Functional Test, 3LP-1 and 3LP-2

PT/0/A/0400/15 SSF Auxiliary Service Water Pump Test

Surveillance tests reviewed were as follows:

WR 590188 Weekly PM of Keowee Turbine, Governor, and

Generator

WR 56842 Keowee Underground Feeder Interlock Test on ACB 3

and ACB 4

No violations or deviations were identified.

7. Maintenance Activities

Maintenance activities were observed and/or reviewed during the reporting

period to verify that work was performed by qualified personnel and that

approved procedures in use adequately described work that was not within the

skill of the trade. Activities, procedures and work requests were examined

to veri fy proper authorization to begin work, provisions for fire,

cleanliness, and exposure control, proper return of equipment to service,

and that limiting conditions for operation were met.

Maintenance work witnessed in whole or in part was as follows:

WR 52861D Verify Operability of 3LP-1

WR 25014B 3LP-2 Would Not Operate When Required to During

Shutdown.

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Maintenance procedures reviewed are as follows:

WR 25032B Disassembly and Maintenance on 3LP-17

WR 20077B 3LP-2 Failed to Open Electrically or Mechanically

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WR 201438 3LP-2 Will Not Open Manually

No violations or deviations were identified.

8. Unit-3 Reactor Trip

On_0ctober 24 at 1:28 a.m. Unit 3 tripped from 10% power due to a loss of

feedwater. The trip was caused by a faulty auxiliary steam pressure

regulator. Operator' action in opening the main feedwater regulating valves

then caused the one feedwater pump which was operating to overspeed,

tripping the pump on high discharge pressure. Loss of both main feedwater

pumps resulted in an anticipatory reactor trip. The emergency feedwater

pumps responded appropriately to provide feedwater to the steam generators.

Other systems responded as required. There was no engineered safeguards

actuation. Following repair of the faulty regulator the reactor was taken

critical and returned to power operations.

No-violations or deviations were identified.

9. Operability of 3LP-2 (Low Pressure Injection Loop Isolation Valvo)

During a previous shutdown of Unit 3 on March 19, 1985 difficulty was

experienced in initiating decay heat removal because the loop isolation

valve, 3LP-2, failed to open on demand. At that time, the licensee

committed to studying the problem to determine what action should be taken

to assure valve operability (IFI 50-287/85-07-01).

During the shutdown of Unit 3 on October 16, 1985, for repair of 0 ring

leakage, 3LP-2 once again failed to open on demand. Operations personnel,

in order to open the valve for decay heat removal, had to go to the valve

breaker and ' stick' the breaker. This involves using an insulated stick to

hold the contractor closed, bypassing the torque overloads so that increased

torque can be applied. I&E personnel were on hand using an ammeter to

prevent overload and possible burnout of the motor operator.

This particular valve, on all three units, has a history of problems in

opening on demand. Several years ago the valve operators were changed to a

significantly smaller size after the stem of one of the valves was damaged

by the large operator installed at that time. The torque switch setting on

3LP-2 was then set at 300 foot pounds. Based on the recent problems with

this valve, the licensee discussed the torque switch settings with the

manufacturer. The result is a new higher torque switch setting; the change

was effected on 3LP-2 and 3LP-1 during the outage beginning on October 16.

The - valves were successfully tested after these changes were made.

' Operability of these valves will continue to be monitored by the residents.

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Following several incidents involving this valve on Units 1 and 2, the

station Onsite Review Group'(OSRG) recommended the installation of a bypass

line around the loop isolation valves, LP-1 and LP-2, in order to provide

assurance that decay heat removal could be initiated. This recommendation-

was the: same as that proposed by-Babcock & Wilcox for plants with single -

drop lines. However, the licensee has not adopted this recommendation.

The ' resident inspectors became aware of recent problems with 3LP-2 on

October 17. Operations confirmed the problems in getting the valve to open.

The inspectors could not find any discussion of these problems in either the

Reactor Operators' (RO) log or the Senior Reactor Operator's (SRO) log.

. Failure to log significant events prevents these problems from reaching

higher levels of management and also inhibits the reporting of these

problems by the appropriate station personnel. Failure to log the

malfunction of 3LP-2 is an apparent violation of TS and Station Directives;

Violation - Failure to document the malfunction of 3LP-2 in the RO or SRO

log (287/85-37-01).

10 CFR 50.73 (vii) requires a Licensee Event Report (LER) to be issued in

any event where a single cause or condition caused at least one independent

train or channel to become inoperable in multiple systems or two independent

trains or channels to become inoperable in a single system designed to ..

(B) remove residual heat. The licensee will report the malfunction of 3LP-2

as an LER.

10. Mispositioned Containment Isolation Valve, Unit 2

On October 8, while conducting - the quarterly containment verification

checklist on Unit 2, the Performance group found containment isolation valve

2LRT-38 in the open position. This valve is required to be closed for

containment integrity. It was last verified closed prior to Unit 2 startup

by two separate procedures. These procedures were Operations and

Performance checklists conducted on July 6 and July 7,1985, respectively.

After finding -the valve open, Performance pressurized the line to verify

that the inboard valve, 2LRT-39, was closed. The valve is on a 1/4"

instrument line from the penetration room into the reactor building used for

leak . testing of penetrations. In the penetration room the valve is

approximately 20 feet above the floor next to the reactor building wall.

The 1/4" line terminates in a quick disconnect which seals the line when

disconnected. Therefore even though 2LRT-38 was open, the line was sealed.

The residents reviewed licensee actions and procedures involved to verify

that there was no open line into containment. The Onsite Review Committee

(OSRG) is investigating this incident. This mispositioned valve is a

violation but will not be cited since it meets the NRC enforcement guidance

of licensee identified violations. The residents will continue to follow

this situation. This will be listed as inspector followup item

270/85-37-02; mispositioned containment isolation valve.

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ll. Keowee Hydro Station Inspection

On October 9,1985, the inspectors toured and inspected the Keowee hydro

station. The recently completed Keowee modification which installed new

batteries was inspected. These batteries are required as backup for

instrumentation and control at Keowee hydro. The battery installation

includes a new seismic support structure. The inspectors also reviewed

controlled copies of safety related procedures in addition to the last

weekly and monthly surveillances.

12. Verification of Surveillance Tests

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The inspectors completed their review to determine that surveillance testing

required for Unit 3 prior to startup from the recent refueling outage had

been completed. In general, there were fewer difficulties encountered

during this review than in a similar review for Unit 2 described in report

-270/85-12. However, one problem was noted. When reviewing the status of

procedures required by TS, it was noted that for one TS requirement, Table

4.1-1, item 36, confusion existed between licensee groups as to the

procedure performed to satisfy the requirement. After some deliberation the

licensee determined that the procedure in question is a Chemistry Department

procedure. The inspectors agreed with this determination and reviewed its

status to enture compliance.

As discussed in report 270/85-12, the licensee is pursuing the revision of a

station ' directive to provide a detailed cross reference of procedures

performed for TS compliance. This cross reference should provide an

accurate accounting for all station groups, management, and the NRC. The

licensee has a target completion date of January, 1986 to complete this

revision. This will be listed as inspector followup item, IFI 287/85-37-03:

Station directive revision to cross reference technical specifications.

13. Inspector Followup Items

(Closed) IFI 269/85-03-02 Verification of performance tests utilizing

installed instrumentation. Performance Manual section 4.14, approved

March 18, 1985, ' describes the method to ensure that installed plant

instrumentation, used in determining safety related equipment operability,

has been calibrated within the required intervals and is evaluated when

found out of tolerance. This item is closed.

(Closed) IFI 269,270,287/85-10-02 Modifications and training concerning

power loss. The inspectors reviewed the additional operator training, .

procedural revisions, and station modifications and have determined them to

be acceptable. This item is closed.

(Closed) IFI 287/85-32-01 Additional training on shutdown margin

calculations. An operations training package on performing the appropriate

shutdown margin calculations was completed on October 28, 1985. The

resident inspector reviewed the package. This item is closed.

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14. Review of Licensee Event Reports

The inspectors reviewed nonroutine event reports to verify that report

details met license requirements, identified the cause of the event,

described corrective actions appropriate for the identified cause, and

adequately addressed the event and any generic implications. In addition,

as appropriate, the inspectors examined operating and maintenance logs, and

records and internal investigation reports.

Personnel were interviewed to verify that the report accurately reflected

the circumstances of the event, that the corrective action had been taken or

responsibility assigned to assure completion, and that the event was

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reviewed by the licensee, as stipulated in the TS. The following event

reports were reviewed:

(Closed) LER 269/84-03 Pie gamma scanner rotated over spent fuel

assemblies. This incident was reviewed and the inspector followup item

(269/84-23-01) closed in report 269/85-12. This LER is closed.

(Closed) LER 269/83-01 Single failure in the Keowee Woodward Governor

System could prevent automatic actuation of emergency power due to design

deficiency. A design study was completed resulting in station modifications

under NSM 2189, completed in June 1985, to eliminate the design flaw. This

LER is closed.

(Closed) LER 269/83-05 Double isolation criteria was not met for the

standby shutdown facility makeup water pump due to design deficiency. The

design has been corrected, valves installed, and drawings changed. This LER

is closed.

(Closed) LER 269/85-01 Failure of ES power supply. The power supply was

lost due to a failed component in the circuitry. The power supply was

l replaced and electrolytic capacitors will be replaced in RPS and ESF power

supplies on all units. This LER is closed.

15. IE Bulletin Review

Response to IE Bulletins were reviewed and, where appropriate, inspected at

the site. The following bulletins has been resolved.

(Closed) IE Bulletin 84-03 Refueling water cavity seal.

16. Information Meeting with Local Officials (94600)

On October 30, 1985 the inspectors met with the County Administrator of

Pickens County at his office in Pickens, South Carolina. On November 4 the

inspectors met with the Oconee County Supervisor at his office in Walhalla,

South Carolina. The purpose of the meetings was to familiarize the county

l officials with the resident inspectors and their duties; to explain the

! mission of the NRC in general, to review lines of communication and to hear

any comments the officials might have.

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In general, both men were satisfied with relationships with the licensee.

One of them expressed concern with communications with the Oconee site

during an Alert in April 1985. After the discussions with the official and

with Oconee emergency preparedness personnel, the inspectors believe the

problems have been corrected. The officials were encouraged to call the

inspectors for information, if needed, and they were provided with Regional

telephone numbers.

The inspectors visited the Public Document Room at the Oconee County Library

in Walhalla. They were favorably impressed with the facilities, the

condition and storage of records, and the timeliness with which documents

were filed.

17. Site Drill

On October 25 the inspectors participated in an emergency drill. The drill

was conducted with the Technical Support Center (TSC) and supporting groups

situated in the training center. The simulated problem, a ruptured main

steam line, was programmed into the simulator which wa: manned by an

operating crew in refresher training. The drill appeared to be an

improvement on those held in the past in that operator actions and

recommendations by the TSC could be acted upon by the simulator and produce

a more realistic exercise.

18. Onsite Review Group (403018)

The OSRG organizational charter was reviewed to determine the specific

duties of the OSRG. Seven procedures that discuss the various functions of

the OSRG were reviewed and an interview was held with the chairman to

discuss the OSRG duties. Of the three basic duties, two were verified as

being performed as required. These are: (1) Review and dissemination of

operating experience; and (2) Preparing incident reports. The review and

dissemination of operating experience will be followed up to determine if

the individual groups are distributing the OSRG information to the proper

personnel.

The third duty; the review of routine in plant activities for the purpose of

identifying deficiencies and/or deviations in programs, management control,

and work practices is being evaluated. The experience level of the OSRG

members was discussed with the chairman. The residents will followup with

the remainder of the evaluation in the next report.

19. Facility Modifications (37701)

The inspectors began a review of selected test procedures performed during

checkout of the Standby Shutdown Facility (SSF) which was declared operable

in October, 1985. Tests reviewed to date are as follows:

TT/3/A/0400/08 SSF - RC Makeup Pump Integrated Test

TT/3/A/0400/09 Local Type C Leak Rate Test on Penetration 17

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TT/2/A/0400/07 SSF - RC Makeup Pump Flow Verification Test

TT/0/A/0400/12 SSF Diesel Generator Initial Load Test

TT/3/A/0400/10 SSF Transfer Control Switch

TT/0/A/0400/05 SSF Auxiliary Service Water Pump Test

TT/2/A/0400/08 SSF RC Makeup Pump Integrated Test

TT/1/A/0400/08 SSF RC Makeup Pump Integrated Test

TT/2/A/0400/07 SSF RC Makeup Pump Performance Test

The only data which the inspector questioned concerned the makeup system

pump output. The test procedure gave an expected range of 23 to 27 gpm at

approximately 2000 psig. In a test performed on June 21, 1985, at 1975

psig, the Unit 2 pump provided 24.5 gpm indicated flow and 25 gpm measured

flow. In a test performed on November 23, 1984 the Unit 1 pump provided

24.25 gpm indicated at 2275 psig. Design information provided to NRR had

listed 26 gpm output. The licensee has discussed the lower delivery rate

with NRR and has stated that the delivered flow exceeds system requirements.

While discussing pump performance with licensee engineers, the inspector was

informed that the pumps will be modified to provide greater piston

displacement and increased flow with no loss of discharge pressure. This

item will not be listed as a followup item since it is already open with

NRR.

Review of test procedures and data will continue in a subsequent inspection.

IE Bulletin 79-23 pointed out a potential diesel generator failure and

requested a response from licensees on certain circuitry questions and

requested a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> full load test. At the time the bulletin was issued,

Oconee had no emergency power diesels. The inspector has requested Duke to

verify that the SSF Diesel generator meets the requirements of Bulletin

79-23. This information will be reviewed when received.

No violations or deviations were identified.

20. Main Steam Code Safety Valves

Delayed reseating of main steam safety valves has been discussed in several

reports during the past year, including 269/84-32, 85-01, and 85-07. Report

No. 269/85-07 described the program the licensee had instituted to rebuild

four of the valves on each refueling outage. In addition to the scheduled

work, during the Unit I shutdown for steam generator tube leaks on

October 7-18, 1985, the licensee reworked code safety valves 2, 4, and 10,

Valves 2, 4, and 10 on Unit I had been the primary offenders on late

reseating. On the recent shutdown these valves were recut, lapped, and the

blowdown rings adjusted. Valve No. 4 was found to have some gouges in a

bushing which could have caused the stem to hang up. Future performance

will determine the success of the rework.

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21. Maintenance on 3LP-17, Low Pressure Injection (LPI) Valve

The inspectors reviewed in detail the maintenance package on valve 3LP-17,

the LPI discharge valve. The inspectors were concerned about the leak

tightness of the valve because the completed procedure indicated that the

valve disc and seat had not been lapped in as is normally done. Further

investigation revealed that, under the inservice inspection program, the

valve is not required to be leak tight. There are two check valves

protecting the LPI system against overpressure.

The inspectors reviewed with Maintenance Department management the work done

on the valve. Maintenance performed was extensive. Maintenance agreed that

the procedure did not reflect all the details of the maintenance but that it

was documented on the work request.

No violations or deviations were identified.